Drill bit with plural set and single set blade configuration

ABSTRACT

Disclosed within is a drill bit with a plural set of blades having redundant cutter elements and single sets of blades having unique cutter element arrangements. The redundant cutter elements have equivalent longitudinal and axial spacing as corresponding cutter elements. The distance from a longitudinal axis of the bit to a redundant cutter element is equivalent to the distance from the longitudinal axis to the corresponding cutter element.

CROSS-REFERENCE TO RELATED APPLICATIONS

Not Applicable.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not Applicable.

BACKGROUND

Embodiments of the present invention relate generally to drill bits and,more particularly, to fixed-cutter bits designed to shift orientation ofthe bit axis in a predetermined direction as it drills.

Drill bits, in general, are well known in the art. The bit is attachedto the lower end of the drill string and is typically rotated byrotating the drill string at the surface or by a down hole motor, or byboth methods. The bit is typically cleaned and cooled during drilling bythe flow of drilling fluid out of one or more nozzles on the bit face.The fluid is pumped down the drill string, flows across the bit face,removing cuttings and cooling the bit, and then flows back to thesurface through the annulus between the drill string and the boreholewall.

The cost of drilling a borehole is proportional to the length of time ittakes to drill the borehole to the desired depth and location. Thedrilling time, in turn, is greatly affected by the number of times thedrill bit must be changed in order to reach the targeted depth orformation. This is the case because each time the bit is changed theentire drill string, which may be miles long, must be retrieved from theborehole, section by section. Once the drill string has been retrievedand the new bit installed, the new bit must be lowered to the bottom ofthe borehole on the drill string, which again must be constructedsection by section. This process, known as a “trip” of the drill string,requires considerable time, effort and expense. Accordingly, it isalways desirable to minimize the number of trips that must be made in agiven well.

In recent years a majority of bits have been designed using hardpolycrystalline diamond compacts (PDC) as cutting or shearing elements.The cutting elements or cutters are mounted on a rotary bit and orientedso that each PDC engages the rock face at a desired angle. The PDC bithas become an industry standard for cutting formations of grosslyvarying hardnesses. The cutting elements used in such bits are formed ofextremely hard materials and include a layer of polycrystalline diamondmaterial. In the typical PDC bit, each cutter element or assemblycomprises an elongate and generally cylindrical support member which isreceived and secured in a pocket formed in the surface of the bit body.A cutter element typically has a hard cutting layer of polycrystallinediamond or other superabrasive material such as cubic boron nitride,thermally stable diamond, polycrystalline cubic boron nitride, orultrahard tungsten carbide (meaning a tungsten carbide material having awear-resistance that is greater than the wear-resistance of the materialforming the substrate) as well as mixtures or combinations of thesematerials. The cutting layer is exposed on one end of its supportmember, which is typically formed of tungsten carbide. As used herein,reference to a “PDC” bit or “PDC” cutting element includes superabrasivematerials such as polycrystalline diamond, cubic boron nitride,thermally stable diamond, polycrystalline cubic boron nitride, orultrahard tungsten carbide.

The configuration or layout of the PDC cutters on a bit face varieswidely, depending on a number of factors. One of these is the formationitself, as different cutting element layouts cut the various stratadifferently. In running a bit, the driller may also consider weight onbit, the weight and type of drilling fluid, and the available orachievable operating regime. Additionally, a desirable characteristic ofthe bit is that it be “stable” and resist vibration, the most severetype or mode of which is “whirl,” which is a term used to describe thephenomenon wherein a drill bit rotates about an axis that is offset fromthe geometric center of the drill bit. Whirling subjects the cuttingelements on the bit to increased loading, which may cause the prematurewearing or destruction of the cutting elements and a loss of penetrationrate. Alternatively, U.S. Pat. Nos. 5,109,935 and 5,010,789 disclosetechniques for reducing whirl by compensating for imbalance in acontrolled manner, the contents of which are hereby incorporated byreference. In general, optimization of cutter placement and orientationand overall design of the bit have been the objectives of extensiveresearch efforts.

Directional and horizontal drilling have also been the subject of muchresearch. Directional and horizontal drilling involves deviation of theborehole from vertical. Frequently, this drilling program results inboreholes whose remote ends are approximately horizontal. Advancementsin measurement while drilling (MWD) technology have made it possible totrack the position and orientation of the wellbore very closely. At thesame time, more extensive and more accurate information about thelocation of the target formation is now available to drillers as aresult of improved logging techniques and methods, such as geosteering.These increases in available information have raised the expectationsfor drilling performance. For example, a driller today may target arelatively narrow, horizontal oil-bearing stratum, and may wish tomaintain the borehole within the stratum once the borehole has enteredthe stratum. In more complex scenarios, highly specialized “designdrilling” techniques are preferred, with highly tortuous well pathshaving multiple directional changes of two or more bends lying indifferent planes.

A common way to control the direction in which the bit is drilling is tosteer using a turbine, downhole motor with a bent sub and/or housing. Asshown in FIG. 1, a simplified version of a downhole steering systemaccording to the prior art comprises a rig 1, drill string 2 having amotor 6 with or without a bent sub 4, and drill bit 8. The motor 6, withor without a bent sub 4, forms part of the bottom hole assembly (BHA).These BHA components are attached to the lower end of the drill string 2adjacent the bit 8. When not rotating, the bent sub 4 causes the bitface to be canted with respect to the tool axis. The motor is capable ofconverting fluid pressure from drilling fluid pumped down the drillstring into rotational energy at the bit. This presents the option ofrotating the bit without rotating the drill string. When a downholemotor is used with a bent housing and the drill string is not rotated,the rotating action of the motor normally causes the bit to drill a holethat is deviated in the direction of the bend in the housing. When thedrill string is rotated, the borehole normally maintains direction,regardless of whether a downhole motor is used, as the bent housingrotates along with the drill string and thus no longer orients the bitin a particular direction. Hence, a bent housing and downhole motor areeffective for deviating a borehole.

When a well is substantially deviated by several degrees from verticaland has a substantial inclination, such as by more than 30 degrees, thefactors influencing drilling and steering change as compared to those ofa vertical well. This change in factors reduces operational efficiencyfor a number of reasons.

First, operational parameters such as weight on bit (WOB) and RPM have alarge influence on the bit's rate of penetration, as well as its abilityto achieve and maintain the required well bore trajectory. As the well'sinclination increases and approaches horizontal, it becomes much moredifficult to apply weight on bit effectively, as the well bottom is nolonger aligned with the force of gravity. Furthermore, the increasingbend in the drill string means that downward force applied to the stringat the surface is less likely to be translated into WOB, and is morelikely to increase loading that can cause the buckling or deforming ofthe drill string. Thus, attempting to steer with a downhole motor and abent sub normally reduces the achievable rate of penetration (ROP) ofthe operation, and makes tool phase control very difficult.

Second, using the motor to change the azimuth or inclination of the wellbore without rotating the drill string, a process commonly referred toas “sliding,” means that the drilling fluid in most of the length of theannulus is not subject to the rotational shear that it would experienceif the drill string were rotating. Drilling fluids tend to bethixotropic, so the loss of this shear adversely affects the ability ofthe fluid to carry cuttings out of the hole. Thus, in deviated holesthat are being drilled with the downhole motor alone, cuttings tend tosettle on the bottom or low side of the hole. This increases boreholedrag, making weight-on-bit transmission to the bit very difficult andcausing problems with tool phase control and prediction. This difficultymakes the sliding operation very inefficient and time consuming

Third, drilling with the downhole motor alone during sliding deprivesthe driller of the advantage of a significant source of rotationalenergy, namely the surface equipment that would otherwise rotate thedrill string and reduce borehole drag and torque. The drill string,which is connected to the surface rotation equipment, is not rotatedduring drilling with a downhole motor during sliding. Additionally,drilling with the motor alone means that a large fraction of the fluidenergy is consumed in the form of a pressure drop across the motor inorder to provide the rotational energy that would otherwise be providedby equipment at the surface. Thus, when surface equipment is used torotate the drill string and the bit, significantly more power isavailable downhole and drilling is faster. This power can be used torotate the bit or to provide more hydraulic energy at the bit face, forbetter cleaning and faster drilling.

In addition to the directional drilling described in the discussion ofFIG. 1, it is also desirable to have a drill bit that is capable ofreturning to a vertical drilling orientation (without the aid of anexternal steering mechanism such as turbine or bent sub) should the bitinadvertently deviate from vertical. The ability of a bit to return to avertical path after deviating from such a path is known in the art as“dropping”. In order to effect dropping, such a drill bit must also havethe capability of drilling or penetrating the earth in a direction thatis not parallel with the longitudinal axis of the bit. It is thereforedesirable to have cutting elements on the side of the bit to allow forsuch cutting action.

As shown in the schematic view of FIG. 2, a drillstring assembly 50,consisting of a drill string 53 and a bit 51, is shown drilling aborehole 55 that has deviated from vertical. Drillstring assembly 50 hasa weight vector 52 that consists of an axial component 54 and a normalcomponent 56. Unlike the directional drilling operations describedabove, such deviations from vertical are sometimes unintentional, and itis desirable in many instances to return drilling assembly 50 to avertical orientation while drilling. In such a case, it necessary fordrill bit 51 to drill in a direction that is not parallel to axialvector 54. This is accomplished by removing material from a side wall57, rather than a bottom portion 53, of borehole 55. As explained inmore detail below, the ability to remove material from side wall 57 isenhanced when bit 51 generates increased forces parallel to normalcomponent 56 during operation.

Drill bits with asymmetric blade designs have been used to generateforces during rotation that are not parallel to axial vector 54. Theasymmetric blade designs typically include “active” regions of cutters,which extend a certain distance from the center axis and the end (orface) of the bit, as well as “passive” regions of cutters, in which thecutters are slightly recessed from the active cutter positions. Thegeneration of these off-axis forces enhance the dropping tendencies ofthe bit by increasing the loading on the side of the bit and reducingthe tendencies of the bit to whirl. However, the asymmetric design ofthe blades can sometimes decrease the durability of the blades as aresult of the increased loading placed on the active cutters and thefact that the passive cutters generally do not actively drill theformation until there has been significant wear on the active cutters.

For all of these reasons, it is desirable to provide a bit that remainsstable during operation and allows for off-axis drilling by exerting aforce against the side of the borehole. It is further desired to providesuch a device that exhibits high durability characteristics by providinga large number of cutters that actively remove material from theborehole during operation.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a conventional drilling system;

FIG. 2 is a schematic view of a prior art drill bit on a drill string;

FIG. 3 is a perspective view of a prior art drill bit;

FIG. 4 is a section view of the prior art bit of FIG. 3;

FIG. 5 is an end view of one embodiment of a drill bit made inaccordance with the disclosure herein;

FIG. 6 is a partial section view of the drill bit of FIG. 5;

FIG. 7 is a partial section view of the drill bit of FIG. 5;

FIG. 8 is an end view of an alternative embodiment of a drill bit;

FIG. 9 is an end view of another alternative embodiment of a drill bit;and

FIG. 10 is an end view of another alternative embodiment of a drill bit.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

A known drill bit is shown in FIG. 3. Bit 10 is a fixed cutter bit,sometimes referred to as a drag bit, and is preferably a PDC bit adaptedfor drilling through formations of rock to form a borehole. Bit 10generally includes a bit body having a shank 13, and a threadedconnection or pin 16 for connecting bit 10 to a drill string that isemployed to rotate the bit for drilling the borehole. Bit 10 furtherincludes a central axis 11 and a cutting structure on the face 14 of thedrill bit. The cutting structure includes various PDC cutter elements 40with a backing portion 38 on a plurality of blades 37 extending radiallyfrom the center of the cutting face 36. Also shown in FIG. 3 are gagepads 12 and gage trimmers 61, the outer surface of which are at thediameter of the bit and establish the size of the bit. Thus, a 12″ bitwill have gage pads 12 and gage trimmers 61 at approximately 6″ from thecenter of the bit.

Referring now to FIG. 4, a profile of bit 10 is shown as it would appearwith all cutter elements 40 shown overlapping in rotated profile. Asshown in this figure, blades 37 include blade profiles 39. The drill bitbody 10 includes a face region 14 and a gage pad region 12 for the drillbit. The action of cutters 40 drills the borehole while the drill bitbody 10 rotates. Downwardly extending flow passages 21 have nozzles orports 22 disposed at their lowermost ends. Bit 10 includes six such flowpassages 21 and nozzles 22. The flow passages 21 are in fluidcommunication with central bore 17. Together, passages 21 and nozzles 22serve to distribute drilling fluid around the cutter elements 40 forflushing drilled formation from the bottom of the borehole and away fromthe cutting faces 44 of cutter elements 40 during drilling. Amongstseveral other functions, the drilling fluid also serves to cool thecutter elements 40 during drilling.

Blade profiles 39 and bit face 20 may be said to be divided into threedifferent regions 24, 26, and 28. The central region of the bit face 20is identified by reference numeral 24 and is concave in this example.Adjacent central region 24 is the shoulder or the upturned curve region26. Next to shoulder 26 is the gage region 28 which is the portion ofthe bit face 20 which defines the diameter or gage of the borehole beingdrilled by bit 10. Cutter elements 40 are disposed along each of blades37 in regions 24, 26 and 28.

Referring now to FIG. 5, an end view of one embodiment of a bit 110 isshown with a cutting face 114 disposed around a longitudinal or bit axis111. A plurality of blades 137-142 project from cutting face 114 andextend radially outward from axis 111. Blades 137-142 comprise aplurality of cutter elements 150 of varying radial and axial positions,as more fully described below. Bit 110 further includes a plurality ofnozzles 122 that distribute drilling fluid as described above. Thespecific locations of the cutter elements 150 are shown in bit 110 forpurpose of example only, and other embodiments may have differentarrangements of cutter elements, including, for example, blades that aremore curved than those shown in FIG. 5.

Referring now to FIG. 6, a partial section view of bit 110 taken atblade 137 shows the orientation of cutter elements 150 arranged on blade137. In addition, a central bore 115 is shown extending from a pin end116 in fluid communication with a fluid passage 121 and nozzle 122. Asshown in FIG. 6, the center of each cutter element 150 is at a radialposition that is a predetermined distance from longitudinal axis 111. Inaddition, each cutter element 150 is located at an axial position thatis a predetermined distance from a reference plane “A” that isperpendicular to longitudinal axis 111. For example, a specific cutterelement 153 is located a distance X1 from longitudinal axis 111 and adistance Y1 from plane A, while cutter element 151 is located a distanceX2 from longitudinal axis 111 and Y2 from plane A.

Referring back now to FIG. 5, for each cutter element 150 on blade 138,there is a corresponding cutter element 150 on blade 137 that is locatedat the same relative radial and axial positions. For example, cutterelement 153 on blade 137 has a cutting face that is located at the samerelative radial and axial position as cutter element 154 on blade 138.More specifically, both cutter elements 153 and 154 are located the sameradial distance from longitudinal axis 111. In addition, both cutterelements 153 and 154 are located the same axial distance from a planethat is perpendicular to longitudinal axis 111 (such as plane A in FIG.6). Similarly, cutter elements 151 and 152 are also equidistant fromlongitudinal axis 111 and equidistant from a plane that is perpendicularto longitudinal axis 111. Thus, when viewed in rotated profile, theprofile of the cutting faces of cutting elements 151 and 152 would beprecisely aligned. If the two cutting face profiles are in exactly thesame position, they may be referred to as “redundant” cutter elements.

In addition, as explained more fully below, a redundant cutting faceprofile may also be recessed 0.020 inches to 0.060 inches from acorresponding cutting face profile. For example, in other embodiments,elements 152 and 154 may be slightly retracted or recessed from thelocations of cutter elements 151 and 153, respectively. In certainembodiments, the position of the cutter elements on one blade can berecessed in a direction that is perpendicular to the face of cutterelement. Referring now to FIG. 7, a section view of cutter element 152taken along line 7-7 in FIG. 5 reveals cutter element 152 affixed toblade 138. Cutter element 152 includes a cutting face 160 disposed on abacking element 155.

In certain embodiments, cutter element 152 can be recessed relative tothe position of cutter element 151. For example, referring still to FIG.7, cutter element 152 can be recessed approximately 0.020 inches to0.030 inches in the direction represented by an arrow “B”, which isparallel to a planar front surface 161 of cutting face 160. Retractionin the direction represented by arrow “B” is commonly referred to asretraction along the “normal line” of the cutter element. In still otherembodiments, cutter element 152 can be recessed in a direction parallelto longitudinal axis 111, so that the distance from plane A (shown inFIG. 6) is approximately 0.020 inches to 0.060 inches less than thecorresponding distance for cutter element 151. In such embodiments, therecessed cutter elements will be slightly closer to the pin end 116.

Referring back now to FIG. 5, as previously stated, for each cutterelement 150 on blade 138, there is a corresponding cutter element 150 onblade 137 that is located at the same relative radial and axialpositions and has the same size and shape as the cutter element on blade138. The additional blades 139-42, however, each have an arrangement ofcutter elements that is unique, i.e. the arrangement of cutter elementson each additional blade 139-142 is different than the arrangement ofcutter elements on any other blade 137-142. More specifically, theradial and axial position of at least one cutter element on a specificblade 139-142 is not equivalent to the radial and axial position of anycutter element on any other blade 137-142. As commonly described in thefield, each of the blades 139-142 are “single set” blades (i.e., bladeswhich comprise an arrangement of cutter elements that is different thanevery other blade on the bit).

The inclusion of several single set blades enhances the durability ofthe bit by providing a large number of cutters that actively removeformation material to form the wellbore. By providing a large number ofactive cutters, the amount of work that is performed by the each cutteris minimized and the stresses placed on each active cutter are alsoreduced. This reduces the likelihood of a mechanical failure for theactive cutters and enhances the durability of the bit.

In contrast, blades 137 and 138 are “plural set” blades; i.e., eachcutter element on trailing blade 138 is redundant to a correspondingcutter element preceding blade 137. Blade 138 is considered the trailingblade because it follows blade 137 as bit 110 rotates counter-clockwiseduring drilling. It should be noted that in a plural set of blades, thepreceding blade may comprise cutter elements in positions additional tothose found on the trailing blade, but the reverse is not true.Therefore, each cutter element on trailing blade 138 has a correspondingcutter element on blade 137 that has generally equivalent radial andaxial spacing. The arrangement of cutter elements on the trailing bladeof a plural set of blades is therefore redundant to the arrangement ofcutter elements on the preceding blade.

During rotation of the bit, each redundant cutter element follows inessentially the same path as the corresponding cutter element on thepreceding adjacent blade. The corresponding element on the precedingblade clears away formation material, allowing the redundant element tofollow in the path cleared by the preceding element. As a result, duringrotation the redundant cutter element is subjected to less resistancefrom the earthen material and less wear than the preceding element. Thedecrease in resistance reduces the stresses placed on the redundantelement and can improve the durability of the element by reducing thelikelihood of mechanical failures such as fatigue cracking.

The incorporation of a plural set of blades 137 and 138 in combinationwith single set blades 139-142 creates an asymmetric configuration thatwill generate an imbalance force perpendicular to longitudinal axis 111as bit 110 rotates. This imbalance force will help to push bit 110against the side wall of the borehole during operation, which willstabilize bit 110 and reduce the tendency of bit 110 to whirl, therebyreducing the likelihood of a mechanical failure of bit 110 or thedrillstring.

Generating a force that pushes bit 110 against the sidewall of theborehole can also improve the ability of the bit to drill in a directionthat is not parallel with the longitudinal axis. When bit 110 is pushedagainst the sidewall of the borehole, gage trimmers 61 can engage thesidewall and remove formation material. This allows bit 110 to penetratethe formation and travel in a direction that is not parallel to thelongitudinal axis of bit 110.

While FIG. 5 depicts an embodiment with one pair of plural set bladesand four single set blades, other embodiments may include a differentnumber of total blades or different numbers of blades in the single andplural sets. One example of an alternative embodiment is shown in FIG.8. In this embodiment, a bit 210 includes a plurality of blades 237-242and nozzles 222 distributed about a longitudinal axis 211. Similar tothe previously described embodiment, a plurality of cutter elements 250are distributed on the blades 237-252. In this embodiment, however,blades 238 and 239 include an arrangement of cutter elements that isredundant to the arrangement of cutter elements on blade 237, such thatblades 237-239 form a plural set. In contrast, blades 240-242 eachinclude a unique arrangement of cutter elements resulting in blades240-242 forming single set blades.

Still another embodiment is shown in FIG. 9. In this embodiment, a bit310 includes a plurality of blades 337-344 and nozzles 322 distributedabout a longitudinal axis 311. A plurality of cutter elements 350 aredistributed on the blades 337-344. In this embodiment, blade 338comprises an arrangement of cutter elements that is redundant to thearrangement of cutter elements on blade 337. In addition, blade 340comprises an arrangement of cutter elements that is redundant to thearrangement of cutter elements on blade 339, but not redundant to thatof blade 337 or 338. Bit 310 therefore has two separate plural sets ofblades (blades 337-338 and blades 339-340). Blades 341-344 each have aunique set of cutter elements and form four separate single sets ofblades.

Yet another embodiment is shown in FIG. 10. In this embodiment, a bit410 includes a plurality of blades 437-440 and nozzles 422 distributedabout a longitudinal axis 411. A plurality of cutter elements 450 aredistributed on the blades 437-440. In this embodiment, blade 438comprises an arrangement of cutter elements that is redundant to thearrangement of cutter elements on blade 437. However, blades 439 and 440each comprise a unique arrangement of cutter elements. Bit 410 thereforehas a pair of blades 437-438 that form a plural set of cutter elementsand a pair of blades 339-340 that are each a single set of cutterelements.

While various preferred embodiments have been showed and described,modifications thereof can be made by one skilled in the art withoutdeparting from the spirit and teachings herein. The embodiments hereinare exemplary only, and are not limiting. Many variations andmodifications of the system and apparatus disclosed herein are possibleand within the scope of the invention. For example, other embodimentsmay comprise drill bits with different blade and cutter arrangements ordifferent numbers of blades. Accordingly, the scope of protection is notlimited by the description set out above, but is only limited by theclaims which follow, that scope including all equivalents of the subjectmatter of the claims.

1. A drill bit for drilling a borehole comprising: a bit body with afirst end, a second end and a longitudinal bit axis; a first bladedisposed on said first end of said bit body; a first arrangement ofcutter elements disposed on said first blade; a second blade disposed onsaid first end of said bit body; a second arrangement of cutter elementsdisposed on said second blade, wherein said second arrangement isredundant to said first arrangement; a third blade disposed on saidfirst end of said bit body, wherein said third blade comprises a thirdarrangement of cutter elements and said third arrangement is unique; anda fourth blade disposed on said first end of said bit body, wherein saidfourth blade comprises a fourth arrangement of cutter elements and saidfourth arrangement is unique.
 2. The drill bit of claim 1 wherein eachcutter element on the second blade is the same distance from thelongitudinal bit axis as a corresponding cutter element on the firstblade.
 3. The drill bit of claim 1 wherein each cutter element on thesecond blade is the same distance from a plane perpendicular to thelongitudinal bit axis as a corresponding cutter element disposed on thefirst blade.
 4. The drill bit of claim 1 wherein: each cutter elementcomprises a generally planar face; and a cutter element on the secondblade is recessed from the position of the corresponding cutter elementon the first blade approximately 0.020 inches to 0.060 inches along aline parallel to the generally planar face.
 5. The drill bit of claim ofclaim 1 wherein each cutter element disposed on the second blade isapproximately 0.020 inches to 0.060 inches closer to the second end thana corresponding cutter element disposed on the first blade.
 6. The drillbit of claim 1 wherein the second blade is adjacent to the first blade.7. The drill bit of claim 1 further comprising: a fifth blade disposedon said first end of said bit body; and a fifth arrangement of cutterelements disposed on said fifth blade, wherein said fifth arrangement ofcutter elements is unique and the first blade is adjacent to the secondblade.
 8. The drill bit of claim 7 wherein the first blade is adjacentto the second blade and the fifth blade.
 9. The drill bit of claim 1further comprising: a fifth blade disposed on said first end of said bitbody; a fifth arrangement of cutter elements disposed on said fifthblade, wherein said first arrangement and said second arrangement ofcutter elements is redundant to said fifth arrangement.
 10. The drillbit of claim 1, further comprising: a fifth blade disposed on said firstend of said bit body; a sixth blade disposed on said first end of saidbit body; a fifth arrangement of cutter elements disposed on said fifthblade, wherein said fifth arrangement of cutter elements is unique; anda sixth arrangement of cutter elements disposed on said sixth blade,wherein said sixth arrangement of cutter elements is unique.
 11. Thedrill bit of claim 10, further comprising: a seventh blade disposed onsaid first end of said bit body; a seventh arrangement of cutterelements disposed on said seventh blade, wherein said seventharrangement of cutter elements is unique.
 12. The drill bit of claim 1,further comprising: a fifth blade disposed on said first end of said bitbody; a sixth blade disposed on said first end of said bit body; a fiftharrangement of cutter elements disposed on said fifth blade, whereinsaid first arrangement and said second arrangement of cutter elements isredundant to said fifth arrangement; and a sixth arrangement of cutterelements disposed on said sixth blade, wherein said sixth arrangement ofcutter elements is unique.
 13. The drill bit of claim 12, furthercomprising: a seventh blade disposed on said first end of said bit body;a seventh arrangement of cutter elements disposed on said seventh blade,wherein said seventh arrangement of cutter elements is unique.
 14. Thedrill bit of claim 1, further comprising: a fifth blade disposed on saidfirst end of said bit body; a sixth blade disposed on said first end ofsaid bit body a fifth arrangement of cutter elements disposed on saidfifth blade; and a sixth arrangement of cutter elements disposed on saidsixth blade, wherein said fifth arrangement of cutter elements isredundant to said sixth arrangement.
 15. The drill bit of claim 14,further comprising: a seventh blade disposed on said first end of saidbit body; a seventh arrangement of cutter elements disposed on saidseventh blade, wherein said seventh arrangement of cutter elements isunique.
 16. A drill bit for drilling a borehole comprising: a bit bodycomprising a first end, a second end, and a longitudinal axis; a firstblade disposed on the first end; a second blade disposed on the firstend; at least two additional blades disposed on the first end; and anarrangement of cutter elements disposed on said blades, wherein: saidcutter elements are spaced radially from the longitudinal axis andaxially from a plane perpendicular to the longitudinal axis; said firstblade has a first arrangement of cutter elements; said second blade hasa second arrangement of cutter elements; the second arrangement isgenerally equivalent to at least a portion of the first arrangement; andeach of the additional blades has an arrangement of cutter elements thatis different than the arrangement of cutter elements on any otheradditional blade.
 17. The drill bit of claim 16 wherein the first bladeand the second blade form a plural set of blades and each additionalblade forms a single set.
 18. The drill bit of claim 16 wherein: eachcutter element disposed on the second blade is the same distance fromthe longitudinal axis as a corresponding cutter element disposed on thefirst blade.
 19. The drill bit of claim 16 wherein each cutter elementdisposed on the second blade is the same distance from a planeperpendicular to the longitudinal axis as a corresponding cutter elementdisposed on the first blade.
 20. The drill bit of claim 16 wherein: eachcutter element comprises a generally planar face; and a cutter elementon the second blade is recessed from the position of the correspondingcutter element on the first blade approximately 0.020 inches to 0.060inches in a direction parallel to the generally planar face.
 21. Thedrill bit of claim of claim 16 wherein each cutter element disposed onthe second blade is approximately 0.020 inches to 0.060 inches closer tothe second end than a corresponding cutter element disposed on the firstblade.
 22. A drill bit for drilling a borehole comprising: a bit bodycomprising a first end, a second end, and a longitudinal axis; aplurality of blades disposed on the first end; and a plurality of cutterelements disposed on the blades, the cutter elements spaced radiallyfrom the longitudinal axis and axially from a plane perpendicular to thelongitudinal axis, wherein: each blade has an arrangement of cutterelements; a first blade and a second blade comprise a first plural setof cutter elements; and a third blade comprises a first single set ofcutter elements; and a fourth blade comprises a second single set ofcutter elements.
 23. The drill bit of claim 22 wherein: each cutterelement disposed on the second blade is the same distance from thelongitudinal axis as a corresponding cutter element disposed on thefirst blade.
 24. The drill bit of claim 22 wherein each cutter elementdisposed on the second blade is the same distance from the plane as acorresponding cutter element disposed on the first blade.
 25. The drillbit of claim 22 wherein: each cutter element comprises a generallyplanar face; and a cutter element on the second blade is recessed fromthe position of the corresponding cutter element on the first bladeapproximately 0.020 inches to 0.060 inches in a direction parallel tothe generally planar face.
 26. The drill bit of claim of claim 22wherein each cutter element disposed on the second blade isapproximately 0.020 inches to 0.060 inches farther from a planeperpendicular to the longitudinal axis than a corresponding cutterelement disposed on the first blade.
 27. The drill bit of claim 22wherein: a fifth blade and a sixth blade comprise a second plural set ofcutter elements, wherein said second plural set is not redundant to saidfirst plural set.
 28. The drill bit of claim 27 wherein: a seventh bladecomprises a third single set of cutter elements; and an eighth bladecomprises a fourth single set of cutter elements.
 29. A drill bit fordrilling a borehole comprising: a bit body having a plurality of bladesdisposed thereon; a longitudinal axis; a plurality of cutter elementsdisposed on the blades, wherein each cutter element has a position thatis a radial distance from the longitudinal axis and an axial distancefrom a plane that is perpendicular to the longitudinal axis, wherein: afirst blade has a first arrangement of cutter elements; a second bladehas a second arrangement of cutter elements, wherein the position ofeach cutter element in the second arrangement is equivalent to theposition of a cutter element in the second arrangement; a third blade,wherein the position of a cutter element on the third blade is notequivalent to the position of a cutter element on any other blade; and afourth blade, wherein the position of a cutter element on the fourthblade is not equivalent to the position of a cutter element on any otherblade.